ISO-NE has barred Invenergy’s planned Clear River Energy Center Unit 2 from offering into February’s capacity auction because of permitting delays resulting from local opposition to the natural gas-fired plant in Burrillville, R.I.
Clear River Energy Center project rendering | Invenergy
Invenergy publicized ISO-NE’s decision for Forward Capacity Auction 12 for 2021/22 in a filing Wednesday to the Rhode Island Energy Facility Siting Board.
The board was scheduled to hold its final evidentiary hearings on the $1 billion project this week but postponed them until December after calling for additional public comment hearings on the plant’s water plan. The plant will have two 485-MW natural gas units with fuel oil backup.
In September, the company announced it had reached agreements with the Narragansett Indian Tribe and water trucking company Benn Water & Heavy Transport to serve as supplemental water suppliers for the plant if it needs more than the primary supplier, the Town of Johnston, R.I., can provide. State regulators had required the company to identify the backup suppliers following a lawsuit by the Town of Burrillville and the Conservation Law Foundation challenging the Johnston supply contract.
The company said the plant will need about 15,000 gallons of water daily, which it says is “90% less than similar plants in the region.”
Invenergy said ISO-NE cited the permitting problems and delays in ordering equipment, although the company said the current schedule would still have allowed it to begin operations by 2021.
“Although Invenergy considered appealing this decision to [FERC], Invenergy could not dispute that there have been permitting delays, and as such, the likelihood that the FERC would overturn ISO-NE’s FCA qualification decision was determined to be remote,” the company said.
Jerry Elmer, senior attorney with the Conservation Law Foundation, told the Providence Journal that “this shows that even the ISO agrees that [the plant] is not needed.”
But in its filing with the siting board, Invenergy included an updated report from PA Consulting Group asserting that the need for the plant is unchanged. The company also said the RTO has told it that Unit 2 is eligible to participate in FCA 13 in 2019.
The report, which assumed a one-year delay in Unit 2’s online date to June 1, 2022, said the delay had no impact on the four findings by the Rhode Island Public Utilities Commission indicating need: Unit 1’s clearing of FCA 10; a significant amount of capacity at-risk for retirement; the state’s location in an import-constrained zone; and the need for capacity above the RTO’s net installed capacity requirement.
Unit 1 is scheduled for commercial operation no earlier than June 2020.
The tax bill introduced by House Republicans on Thursday would trim the wind production tax credit by more than a third and eliminate the credit for electric vehicles while maintaining the tax credit for Southern Co.’s troubled Vogtle nuclear project.
The proposal would repeal the inflation adjustment for the PTC, effectively reducing the PTC from 2.3 cents/kWh in 2016 to 1.5 cents for projects begun after Nov. 2.
| AWEA
The American Wind Energy Association complained that the proposed Tax Cuts and Jobs Act “reneges” on the deal Congress made in 2015, which would phase out the PTC completely over five years.
AWEA CEO Tom Kiernan said the bill is “a retroactive tax hike” that would “pull the rug out from under 100,000 U.S. wind workers and 500 American factories, including some of the fastest growing jobs in the country.”
Under the 2015 legislation, wind projects that started construction in 2015 and 2016 receive the full PTC of 2.4 cents/kWh. Projects that begin construction in 2017 receive 80% of the credit, with those beginning in 2018 reduced to 60% and those in 2019 getting 40%. The credit would be eliminated for projects begun in 2020 and beyond.
Eliminating the inflation adjustment would boost tax receipts by $12.3 billion through 2027, according to a summary released by Republicans on the House Ways and Means Committee.
AWEA also said the law would unfairly change what constitutes the start of project construction. “Investors who put billions of dollars into factory orders and construction contracts cannot go back in time to meet the revised requirements,” it said.
Under current rules, a project is deemed to have commenced construction when it has passed a “physical work” test or shown that 5% or more of the total cost of the facility was paid or incurred. The physical work test is met by activities such as the beginning of excavation for turbines’ foundations or work on step-up transformers.
Developers are required to make “continuous progress” toward completion once construction has begun and must complete the project within four calendar years after the year in which it began construction. The new bill would eliminate the 5% “safe harbor,” disqualifying projects “unless there is a continuous program of construction.”
The wind industry is just one of the potential losers in the bill, which also eliminates the $7,500 tax credit for purchasers of electric vehicles. That would be more bad news for Tesla, which on Wednesday reported a $619 million quarterly loss and said it would not meet its goal of producing 5,000 Model 3 cars per week in 2017. Tesla shares dropped 6.8% Thursday.
The bill also would eliminate the permanent 10% investment tax credit for commercial-scale solar and geothermal power.
But there are also some energy winners.
The Treasury Department would forgo $1.2 billion through 2027 by “harmonizing” the expiration dates and phase-out schedules for ITCs on solar, geothermal, fuel cell, microturbines, combined heat and power system and small wind facilities.
In addition, the bill would remove a 2020 deadline for nuclear plants to claim the 1.8 cents/kWh nuclear production tax credit, a change needed to allow Southern’s overbudget and behind-schedule Vogtle Units 3 and 4 to claim it.
The credit applies to the first 6,000 MW of new nuclear capacity. Because the Vogtle project totals 2,200 MW, and South Carolina Electric & Gas’ V.C. Summer Units 2 and 3 have been canceled, it “will leave a significant amount of remaining capacity that future small modular or advanced reactor projects will be able to access,” the Nuclear Energy Institute said.
LITTLE ROCK, Ark. — SPP’s Regional State Committee will later this month begin taking a lead role in Mountain West Transmission Group’s integration into the RTO, with the first of what will likely be many calls and meetings on the subject.
SPP has identified the RSC as one of the key stakeholder groups in Mountain West’s pursuit of membership. The committee has primary responsibility for cost allocation, financial transmission rights, resource adequacy and remote resources planning within the RTO’s current 14-state footprint.
“This is a wonderful strategic opportunity for SPP,” CEO Nick Brown told RSC members Oct. 30. “Expanding our market and lowering our administrative rates both carry significant benefits to SPP members and significant benefits to the Mountain West Transmission Group.
“Now’s the time to engage … please stay that way,” Brown implored. “The next couple of months will be critical.”
SPP will use a commissioners’ forum to work through several policy issues as the integration process moves into more open forums. Some work will still take place behind closed doors, with the Strategic Planning Committee holding executive sessions Nov. 21 and Dec. 4. (See SPP, Mountain West Integration Work Goes Public.)
Mountain West has asked SPP to expand the RSC to include a group consisting of just the Western states, resulting in a single committee with two regional divisions. It has also proposed a Westside Transmission Owners Committee that would have decision-making authority over cost allocation, zonal changes and transmission revenue requirements in what would become the west side of the RTO.
SPP Vice President of Operations Bruce Rew told the RSC that the Integrated Marketplace continues to work “very well,” despite the growing influence of wind energy in the RTO’s footprint.
Rew said wind will likely become the No. 2 fuel source for 2017, behind only coal. Coal has accounted for 46.9% of the RTO’s fuel mix year-to-date, with wind averaging 22.0% and gas 19.4%, respectively.
Almost 16.7 GW of wind energy is installed and operational in SPP, with another 690 MW registered but not yet operational.
Rew said the RTO came close to setting new records for both wind production and summer peak demand during the third quarter. Wind production peaked at 13.32 GW on Sept. 21, just short of the record of 13.34 GW set in April. On Sept. 22, SPP averaged just more than 12 GW of wind energy for the entire day, Rew said.
Wind penetration during the quarter peaked at 49.41% of system load on Sept. 8. SPP’s record is still 54.47% wind penetration, set in April.
Summer demand peaked at 50.57 GW in July, not far off the all-time peak of 50.62 GW set in 2016.
| SPP
Rew said 197 market participants are currently active in the markets. Of those, 130 are classified as financial-only and 67 as asset-owning. He said the day-ahead market was delayed from posting once in the last 12 months, and the real-time balancing market has successfully solved 99.87% of all intervals.
Kansas’ Albrecht Elected as RSC’s 2018 President
The RSC unanimously elected the Kansas Corporation Commission’s Shari Feist Albrecht as its president for 2018, replacing Missouri Public Service Commissioner Steve Stoll. Albrecht currently serves as the committee’s vice president.
South Dakota Public Utilities Commissioner Kristie Fiegen will become the committee’s vice president next year, with Dennis Grennan of the Nebraska Power Review Board replacing Fiegen as the RSC’s secretary and treasurer.
The committee also approved a 2018 budget of $370,500, with the understanding that $50,000 to $150,000 could be allocated for consulting expenses for its Mountain West work.
PacifiCorp and NV Energy can sell power into the Western Energy Imbalance Market (EIM) at market-based rates, FERC has ruled, reversing a previous finding that had restricted the companies to submitting only cost-based offers (ER17-2934).
The commission imposed the restrictions in late 2015 after finding the two Berkshire Hathaway Energy affiliates had failed to prove that they wouldn’t exercise horizontal market power within the market. At the time, the EIM comprised only the CAISO, PacifiCorp-East (PACE), PacifiCorp-West (PACW) and NVE balancing authority areas (BAAs). It now includes Arizona Public Service, Puget Sound Energy and Portland General Electric.
FERC’s decision goes a long way in relieving PacifiCorp’s market restrictions in the interior West. The utility can now sell into the PacifiCorp-East and PacifiCorp-West areas at market-based rates, and will be able to do the same in Idaho Power’s territory starting next April when that utility joins the EIM | WECC
In their August joint filing with FERC, PacifiCorp and NVE said that the bidding restrictions were “no longer appropriate” because both companies now meet conditions for EIM participation set out in previous FERC orders. They also contended that reliance on cost-based bids ran “contrary to organized market design” and presented the risk of unrecovered costs during some market intervals. (See Berkshire Companies Request EIM Rate Authority.) The utilities contended that the restrictions have created inefficiencies in how they manage hydroelectric resources and respond to intraday fluctuations in natural gas prices.
The companies also provided FERC with analysis by Charles Rivers Associates (CRA) demonstrating there has been little congestion between EIM BAAs since the entry of NVE into the market, supporting the argument that member BAAs should not be considered submarkets subject to market power — a key concern for FERC.
The CRA analysis examined EIM price data from December 2015 to November 2016 to determine the frequency of price discrepancies between CAISO and other EIM BAAs — an indicator of transmission constraints that could warrant concerns about local market power.
CRA’s conclusion: In the 15-minute market, transmission paths appeared to be congested enough to create price separation only 0.7 to 2.4% of the time depending on the BAA; the five-minute market experienced congestion during 0.3 to 6.2% of all intervals, with the higher percentage representing periods when prices deviated by just 1 cent/MWh, what FERC called a “conservative” threshold to test for price separation.
In its Oct. 30 ruling, FERC said it had corroborated those findings.
“We have reviewed this analysis and determined the methodology to be acceptable for an EIM submarket analysis,” the commission wrote. “The commission has previously found that binding constraints in 2.2% of all study hours during an 18-month study period is insufficient evidence to support the existence of a submarket. The price separation instances in this case, which are used here as an indication of binding constraints, are generally in the 2% range, which would indicate a lack of a submarket.”
The commission additionally determined that, having demonstrated the lack of submarkets in the EIM, the two companies have prepared their pivotal supplier and wholesale market share screens consistent with FERC requirements.
“Accordingly, we find it appropriate to lift the default energy bid restriction and allow the Berkshire EIM sellers to bid into the EIM at market-based rates without restriction,” the commission said.
FERC’s decision should help relieve the two companies’ broader market restrictions in the interior West. Last year, the commission also revoked authorization for 21 BHE affiliates, including PacifiCorp and NVE, to sell power at market-based rates in the PACE, PACW, Idaho Power and NorthWestern Energy BAAs. (See Berkshire Market-Based Sales Restricted in 4 Western BAAs.)
While that order still stands, the two companies will immediately have a freer hand to effectively bid power into PACE and PACW through the EIM, and will gain similar access to Idaho Power’s territory starting next April when that utility joins the market.
The Senate on Thursday confirmed Republican Kevin McIntyre and Democrat Richard Glick to FERC, giving the commission a full panel for the first time in two years.
The two were approved on voice votes, putting them in a position to weigh in on Energy Secretary Rick Perry’s controversial proposal to provide price supports to coal and nuclear plants in competitive markets (RM18-1).
McIntyre, the coleader of the global Energy Practice at the law firm Jones Day, will serve out the rest of a term that ends June 2018, and then serve a full term that ends June 2023. Glick, the general counsel for Democrats on the Senate Energy and Natural Resources Committee, will serve a term that ends in June 2022.
The nominations of McIntyre and Glick were approved by the Senate Energy and Natural Resources Committee in September, but their confirmations were blocked last month by Sen. Jim Inhofe (R-Okla.), who complained Senate Democrats were blocking several of President Trump’s other nominees. (See Senate Panel Clears McIntyre, Glick for FERC.)
The two were among more than two dozen appointees approved Thursday.
Once they are sworn in, FERC will have its full five members for the first time since October 2015, when Republican Philip Moeller left the commission. FERC was without a quorum between February, when former Chairman Norman Bay resigned, and August, when Republicans Neil Chatterjee and Robert Powelson joined Commissioner Cheryl LaFleur on the commission. (See FERC Quorum Restored as Powelson, Chatterjee Confirmed.)
Chatterjee welcomed the two in a statement released by FERC. “I’ve enjoyed getting to know Kevin through the confirmation process and am eager to start working with him, and it will be great to reunite with Rich Glick, my former Senate colleague,” he said.
The addition of the two ensures, however, that Chatterjee would need to attract at least two votes for a majority in support of the Department of Energy’s Notice of Proposed Rulemaking to provide “full recovery” of nuclear and coal plant costs. (See FERC Chair Praises Perry’s ‘Bold Leadership’ on NOPR.)
Chatterjee said at a luncheon Wednesday that the federal government may “cast a lifeline” to coal and nuclear power plants while it conducts a long-term review of the country’s power grid. Chatterjee said he was worried that short-term market pressures would force the owners of coal and nuclear plants to close them and later on the country would realize it needed the power they produced.
Although DOE put no price tag on its proposal, estimates of its cost range into the billions. (See Cost Estimates on DOE NOPR: $300 million to $32 billion.) In a conference call with Kentucky reporters Thursday, Chatterjee acknowledged that the policy could result in higher electric bills for some customers. Additional revenue to keep struggling coal plants running “would come from customers in that region, who need the reliability,” he said, according to the Courier Journal. “It’s in these customers’ interests to keep these plants open.”
Chatterjee, like his former boss, Senate Majority Leader Mitch McConnell, is from Kentucky.
During his confirmation hearing, McIntyre said, “FERC is not an entity whose role includes choosing fuels for the generation of electricity.” (See McIntyre to Senate: ‘FERC does not Pick Fuels’.)
MISO has concluded there’s little economic benefit to new transmission connecting Michigan’s Upper Peninsula to Ontario.
Reporting on the results of a study requested by the state, MISO officials told a Nov. 1 Economic Planning Users Group call that none of several potential new lines through the twin Sault Ste. Marie cities on the U.S.-Canada border produces benefits commensurate with their costs over a 20-year span.
“Due to the relatively low transfer capability and relatively high construction cost, none of those transmission ideas provided enough benefit to cover its cost,” said MISO Manager of Economic Studies Zheng Zhou.
Currently there’s no transmission connection between Ontario and the UP, although the Lower Peninsula has connections to the province’s hydropower system. Michigan Gov. Rick Snyder requested the study last August in search of solutions to alleviate persistently high power costs in the UP. (See Michigan Asks MISO to Study Tx Links to Ontario.)
Lower voltage options examined under MISO’s UP to Ontario transmission study | MISO
MISO worked on the study with Ontario’s Independent Electricity System Operator (IESO), which found it could reliably transfer a maximum of 125 MW to the peninsula. Beyond that amount, “significant reliability upgrades would be needed on both systems to increase that transfer capability,” Zhou said.
Economic Studies Senior Engineer Tim Kopp said MISO studied 16 potential new lines, including 161-kV, 230-kV, 345-kV and DC options. It also found that the benefits of a new 400-MW combined cycle plant in Kalkaska County or a 100-MW plant at the nearby Pine River substation would not outweigh their costs either.
MISO did identify benefits over 20 years if a sub-345-kV transmission line allowed 400-MW transfers, but the scenarios showed the local 115-kV system couldn’t reliably support that amount in its current state and would need expensive upgrades.
Final public results of the study will be posted in mid-December, Zhou said.
Customized Energy Solutions’ Ginger Hodge asked if study results would be included in this year’s MISO Transmission Expansion Plan. Zhou said the study was considered ad hoc and not an MTEP study.
Zhou agreed to a request by Michigan Public Service Commission staffer Bonnie Janssen to present the study’s findings at the MISO Board of Directors’ December meeting.
MISO’s study results arrived a week after the PSC approved Upper Michigan Energy Resources Corp.’s $277 million plan to build two reciprocating internal combustion engine stations in the UP in spring (U-18224). Chairman Sally Talberg said the plants will result in a “more reliable and affordable” electric supply for UP customers, including the Tilden Mining operation. Tilden will cover 50% of the capital costs of the plants along with fixed operations and maintenance expenses.
The plants will replace the costly system support resource agreement that keeps the Presque Isle Power Plant running. In October, FERC ruled that ratepayers were overcharged by nearly $23 million for continued Presque Isle operations. (See $23 Million Owed to Ratepayers in Presque Isle SSR Case.)
MISO and PJM have responded to a FERC deficiency letter with a defense and clarification of their proposal to impose stricter rules on pseudo-ties.
In early August, the two RTOs filed identical proposals to permit them to terminate or suspend pseudo-ties that don’t acquire transmission service or follow modeling rules by providing real-time data. The proposals would also allow a balancing authority the ability to redirect pseudo-tie output to avoid exceeding NERC operating limits.
In late September, FERC sent a deficiency letter asking how a native reliability coordinator would commit, de-commit or redispatch pseudo-tied generation to avoid operating limits. The commission also asked the RTOs to clarify rules for suspending terminating pseudo-ties. (See 2nd Deficiency Notice Issued for MISO-PJM Pseudo-Tie Effort.)
In filings Oct. 30, the RTOs defended their proposals, with PJM saying redispatch and recommitment of pseudo-tied generation is essential to maintaining operating limits during localized thermal issues, voltage issues or islanding situations (ER17-2218). MISO also said a redispatch option is crucial during planned transmission outages, forced transmission outages or during periods of heavy system transfers (ER17-2220). PJM added that there would be no limit to the number of times a pseudo-tied generator could be recommitted or redispatched. MISO said pseudo-tied resources would still be eligible to provide reactive supply and voltage control service, a point PJM did not address.
PJM said its 42-month notice to terminate a pseudo-tie is rooted in its three-year advance capacity auction and would give “planning engineers sufficient time to take into consideration the impact of the termination” and pointed out that it is “consistent with the notice requirement that a capacity market seller must give to PJM when it intends to deactivate a generator.”
| MISO, PJM
MISO and PJM said they would only terminate a pseudo-tie under the circumstances described in their respective Tariffs and both would generally try to impose a suspension period first, during which the resource is decommitted or manually dispatched. PJM said termination conditions are “for the most part … tied to a situation in which a pseudo-tie is causing instability on the bulk power system or raising or causing reliability concerns.”
In identical language, MISO and PJM also said they would use a case-specific approach to termination, and would work with generators to address problems and avoid terminations, which they called a “last resort.”
The RTOs have said that they would suspend a pseudo-tie when they are “reasonably” found to pose a reliability risk or don’t follow the rules of their attaining balancing authority. PJM added that the RTOs “expect suspensions to be very exceptional events.”
MISO and PJM proposed that suspensions occur without FERC approval, and that a contested suspension remain in force pending a commission decision.
Meanwhile, MISO is still awaiting final word on its pro forma pseudo-tie agreement for PJM. The agreement was conditionally approved by FERC staff in August before the commission regained its quorum (ER17-1061). The proposal also was the subject of a deficiency notice in the spring. (See FERC Conditionally OKs MISO’s Pseudo-tie Pro Forma.)
VALLEY FORGE, Pa. — While stakeholders remain divided on changes to PJM’s Incremental Auctions, hope remains for reaching a compromise that can be implemented in time for next year’s Base Residual Auction. (See Consensus Fades on PJM Incremental Auction Solution.)
Stakeholders at Tuesday’s meeting of the Incremental Auction Senior Task Force defined where they will and will not budge on their positions. The three main sticking points are the number of IAs per delivery year, at what price PJM should sell excess capacity and what to do about excess commitment credits (ECCs).
Stakeholders appear closest to consensus and willing to negotiate regarding the number of auctions. PJM’s Brian Chmielewski presented the results of a recent poll that found more than two-thirds of voters strongly supported the status quo of an IA for each of the three years between the BRA and the delivery year.
However, most respondents were willing to consider proposals to reduce the number to two. A majority of voters were neutral about an option to have PJM sell capacity in either IA, with 41% opposed. A proposal to limit PJM to selling capacity in the final IA was strongly supported by 38% and opposed by 44%, with 18% neutral.
James Wilson of Wilson Energy Economics, a consultant to consumer advocates for several PJM states, said there’s no reason to reduce the number of IAs, but reducing to two could be acceptable. Carl Johnson, who represents the PJM Public Power Coalition, agreed that his membership was “not willing to fall on our sword” over the issue.
Sell-Back Price
Stakeholders remain divided over the sell-back pricing approach. PJM’s Jeff Bastian argued that the price must be at least what the RTO paid for it in the BRA. “If I’m going to excuse someone from a BRA commitment, why should I pay them?” he asked.
Wilson and Jeff Whitehead of GT Power Group argued PJM should sell for whatever the market will bear. “You may sell some capacity [at the BRA price], but you’re basically pricing yourself out of the market,” Whitehead said.
PJM’s position “doesn’t make much sense,” Wilson said, because the capacity is not as valuable in the IA if the load forecast has been reduced following the BRA. He has argued that PJM needs more accurate load forecasts prior to the BRA.
Bastian later floated an idea that was developed during a meeting break to allow market participants out of their capacity obligations but not excuse them from the daily capacity-shortfall penalties, which equal 120% of the capacity payments. Wilson and Adrien Ford of Old Dominion Electric Cooperative pointed out that the idea is analogous to selling the capacity at the BRA clearing price. Bastian agreed, adding, “you’d have a cleaner settlement report.”
EnerNOC’s Katie Guerry was concerned the idea would reduce liquidity in the IAs because those with capacity obligations could walk away and decide they “won’t even bother” attempting to replace them in the IAs.
Whitehead said the IAs would have to clear above the BRA price for load to benefit. “I think, mathematically, load is better off under what [Bastian] just described,” Whitehead said.
Stakeholders were also split on what to do with ECCs, which are allocated to load-serving entities when reliability requirements decrease below commitments. Currently, LSEs can use ECCs to replace resource commitments. Load has proposed eliminating the ECCs so that the excess committed megawatts, if not otherwise sold in an IA, are retained. The proposal also removes an opportunity for market participants to bypass the intent of any new IA sellback-pricing approach, Susan Bruce, who represents the PJM Industrial Customer Coalition, told RTO Insider in an email.
Johnson said public power organizations “feel entitled” to the ECCs and find them “helpful” for covering EFORd (equivalent forced outage rate – demand) deficiencies while adhering to their business models. As nonprofit entities, public power has a “distaste” for “making money” on the commitments by selling them back, Johnson said. Ford said she agreed with Johnson.
Guerry said that LSEs incur costs to secure commitments. “It’s not all necessarily profit” when they are sold back, she said.
Bruce said she “can appreciate [public power’s] perspective when you have self-supply obligations,” but that “load is getting the short end of the stick.” She also questioned how auditable ECCs would be if customers attempted to negotiate for their proportionate share of them in a retail transaction. She acknowledged some “wiggle room here” to negotiate a different solution but said the “status quo is not an option from a load perspective.”
Chmielewski asked stakeholders to develop new proposals for the task force’s next meeting on Nov. 10.
The IASTF is also charged with resolving a second problem statement and issue charge on the potential for profiting off of replacement capacity. Chmielewski said the issue will be a focus of the next meeting as well. (See “Stakeholders Quibble with, but Eventually Endorse, Replacement Capacity Investigation,” PJM Markets and Reliability and Members Committees Briefs.)
To get the proposals implemented in time for the next BRA in May, they will need to be presented at the January meeting of the Markets and Reliability Committee, he said.
Despite the retirement of more than 3.5 GW of generation, ERCOT said Wednesday it has enough installed capacity available to meet forecasted peak demand through May 2018.
The ISO expects to have almost 81 GW of total capacity available this winter, more than enough to meet a projected peak of more than 61 GW. That would break the winter peak demand record of 59.75 GW, set last January.
ERCOT removed 3,551 MW of recently announced generation retirements from the final seasonal assessment of resource adequacy (SARA) report for the winter season (December-February). That includes 1,200 MW of capacity still being studied to determine whether it is needed to maintain system reliability.
Luminant’s Monticello Power Plant | Luminant
Luminant accounted for most of the retired resources. The company said last month it will shut down three coal plants totaling 4.2 GW by the end of February. (See Vistra Energy to Close 2 More Coal Plants.)
“ERCOT still expects to have sufficient systemwide operating reserves for the winter season,” Pete Warnken, the ISO’s manager of resource adequacy, said Wednesday. “Our studies show this would be the case even with a much higher-than-expected peak demand.”
The winter SARA includes nearly 1.4 GW of mostly renewable capacity. The wind and solar projects are expected to contribute 209 MW to the winter peak.
ERCOT Senior Meteorologist Chris Coleman said he expects a mild winter overall, with some very cold periods in mid-winter.
The ISO’s preliminary assessment for the spring months (March-May) was equally optimistic. Staff projects a season peak of more than 59 GW, and expects to have 80.7 GW of capacity available.
The final spring SARA report will be released in early March.
ERCOT’s most recent Capacity, Demand and Reserves report indicated the ISO had an 18.9% reserve margin for next summer, with margins remaining above 18% the following three years. A revised CDR report incorporating the latest retirements will be released in December.
Calpine reported Wednesday that it earned $225 million in the third quarter ($0.63/share), down 24% from $295 million ($0.83/share) a year earlier.
The decrease was primarily due to “an unfavorable variance in mark-to-market gain/loss, net, and increases in plant operating expense and depreciation and amortization expense,” Calpine said. The decline was partially offset by a higher commodity margin, which the company said was driven by hedge revenues from retail operations and higher regulated capacity revenue.
Calpine’s Sonoma Geothermal Plant north of San Francisco, Calif.
The company, which has agreed to go private in a $5.6 billion deal with Energy Capital Partners and an investors group, lost $47 million in the first nine months of this year, compared with a profit of $68 million in the same period a year ago. Company officials issued the earnings with no previous public notice and no conference call to take questions from analysts. (See Calpine Going Private in $5.6B Deal.)
In a news release announcing the results, CEO Thad Hill said the merger is on track to be completed in the first quarter of 2018. He focused on the company’s response to natural disasters in California and Texas.
“Since our last earnings call, we endured Hurricane Harvey in Texas and the wildfires in Northern California safely and without any material damage to our facilities,” Hill said. “I am particularly proud of team members on the front lines who kept our plants and operations going in the face of adversity.”
Calpine’s Hermiston Power Project natural gas plant in Oregon
Operating revenues were $2.6 billion for the quarter, compared with about $2.4 billion in the same quarter last year. Operating revenues in the first nine months of 2017 were nearly $7 billion, compared with about $5.1 billion in the same period last year.
The company said cash from operating activities rose 21% to $807 million over the first three quarters, “primarily due to a decrease in working capital employed resulting from the period-over-period change in net margining requirements associated with our commodity hedging activity, partially offset by a decrease in income from operations, adjusted for non-cash items.”
